The majority of steam turbine equipped geothermal power generating units are equipped with surface condensers. Because the volume ratio of condensate to vent gas is small, most of the noncondensible gases in the steam—including hydrogen sulfide (H2S)—leave the condenser with the condenser vent gas. Well established processes (Stretford, LoCat, SulFerOx, combustion, regenerative thermal oxidation, etc., hereinafter “primary H2S abatement”) are employed to remove essentially all of the H2S from the vent gas before it is vented to the atmosphere, thereby preventing air pollution by toxic and extremely malodorous H2S.
This simple and usually highly effective method of controlling air pollution becomes much less effective when the steam contains ammonia; notably, in the very large dry steam field in Sonoma County and Lake County, Calif. Ammonia—which is a base—reacts with H2S—which is a weak acid—to produce a nonvolatile salt (ammonium bisulfide, NH4SH) which remains dissolved in the condensate:H2S+NH3→HS−+NH4+  (1)
As a result, a substantial fraction of the H2S (as much as 35%) leaves the condenser dissolved in the condensate instead of with the vent gas. Most of the steam condensate is provided to the cooling tower as make-up water, and—if not further treated—most of the H2S in the condensate would be released from the cooling tower to the atmosphere, causing air pollution.
Several methods have been implemented to minimize release of H2S from the cooling tower, but each has drawbacks.    1. The H2S dissolved in the condensate can be destroyed using chemical oxidation, commonly employing hydrogen peroxide, which is unstable, hazardous and expensive and requires expensive storage tanks and pumps to keep it from decomposing, potentially in an explosive manner. This method of so-called secondary H2S abatement significantly increases the cost of power generated.    2. A catalyst—iron complexed with EDTA, HEDTA or another chelating agent—can be added to the cooling water to catalyze reaction of the H2S with oxygen dissolved in the cooling water before it is released to the atmosphere. Because a 2:1 or greater mole ratio of catalyst to H2S dissolved in the cooling water is required, the consumption and cost of the catalyst (which is lost with cooling tower blowdown and through gradual decomposition) can be large when the amount of H2S dissolved in the condensate is large. Also, colloidal sulfur produced by the oxidation reaction and iron oxide from decomposition of the catalyst produce sediment and deposits that foul the condenser tubing, decreasing thermal efficiency of the power generating unit and necessitating periodic outages to clean the condenser and cooling tower.    3. When the amount of H2S in the condensate is small, microbes present in the cooling water are able to consume most of the H2S before it is emitted from the cooling tower. An appropriate population of microbes must be maintained in the cooling water for this approach to work, requiring tight control of biocide usage. If too little biocide is added to the cooling water, microbes proliferate and foul the condenser tubes and tower fill. If too much biocide is added, the population of microbes decreases to the point that H2S is emitted to the atmosphere. Also, microbial oxidation of H2S produces colloidal sulfur. Even with tight control, some amount of H2S is emitted to the atmosphere, and deposits of biomass and sulfur in the condenser tubes require periodic cleaning.
Therefore, the geothermal industry has devoted much effort to decreasing the amount of H2S that dissolves in the condensate; indeed, surface condensers are commonly employed precisely because they put a larger fraction of the H2S into the vent gas as compared to contact condensers, despite the fact that surface condensers are more expensive and less efficient in terms of power generation than are contact condensers and require more maintenance.
In all cases, carbon dioxide is the major impurity present in geothermal steam and is a major constituent of the condenser vent gas. A small fraction of the CO2 present in the steam dissolves in the condensate inside the condenser, and a small fraction of the CO2 dissolved in the condensate reacts with water to produce carbonic acid, which is a much stronger acid than H2S:CO2+H2O→H2CO3K<0.002  (2)
The carbonic acid reacts with the ammonium bisulfide in the condensate converting it back to H2S which partitions into the vent gas:H2CO3+HS−→H2S+HCO3−  (3)
In principle, the presence of CO2 dissolved in the condensate might be expected to prevent H2S from dissolving in the condensate. Because the solubility of CO2 in warm water is small and the partial pressure of CO2 inside the condenser is small, very little CO2 actually dissolves in the condensate. Furthermore, the reaction of CO2 with water to produce carbonic acid is slow in relation to the limited time is available for the reaction to take place before the condensate falls out from the two phase region inside the condenser and into the hotwell. For this reason, the CO2 in the steam actually has little effect upon the solubility of H2S in the condensate, and fails significantly to decrease the cost and complications of secondary abatement.